The present invention relates to a system using a non-metallic string attached to a downhole tool for performing a downhole operation in a well and more particularly includes a bottom hole assembly disposed on composite coiled tubing. In using the well system for drilling the well, the bottom hole assembly includes a power section for rotating a bit and a motive means for placing weight on the bit. One motive means is a propulsion system for moving the bottom hole assembly within the well.
Many existing wells include hydrocarbon pay zones which were bypassed during drilling and completion because such bypassed zones were not economical to complete and produce. Offshore drilling rigs cost approximately $40 million to build and may cost as much as $250,000 a day to lease. Such costs preclude the use of such expensive rigs to drill and complete these bypassed hydrocarbon pay zones. Presently, there is no cost effective methods of producing many bypassed zones. Thus, often only the larger oil and gas producing zones are completed and produced because those wells are sufficiently productive to justify the cost of drilling and completion using offshore rigs.
Many major oil and gas fields are now paying out and there is a need for a cost effective method of producing these previously bypassed hydrocarbon pay zones. The locations and size of these bypassed hydrocarbon zones are generally known, particularly in the more mature producing fields.
To economically drill and complete the bypassed pay zones in existing wells, it is necessary to eliminate the use of conventional rigs and conventional drilling equipment. One method of producing wells without rigs is the use of metal coiled tubing with a bottom hole assembly. See for example U.S. Pat. Nos. 5,215,151; 5,394,951 and 5,713,422, all hereby incorporated herein by reference. The bottom hole assembly typically includes a downhole motor providing the power to rotate a bit for drilling the borehole. The bottom hole assembly operates only in the sliding mode since the metal coiled tubing is not rotated at the surface like that of steel drill pipe which is rotated by a rotary table on the rig. The bottom hole assembly may include a tractor which engages the borehole wall and applies weight on bit. The tractor is self-propelled and may move in and out of the borehole pushing or pulling the coiled tubing. Another means of applying weight on bit is the use of a thruster. One type thruster pushes off the lower terminal end of the coiled tubing and does not rely upon contacting or gripping the inside wall of the borehole. The depth that can be drilled using a thruster is limited.
One such self-propelled tractor is manufactured by Western Well Tool for propelling a near conventional bottom hole assembly in the borehole. See U.S. Pat. No. 6,003,606, hereby incorporated herein by reference. The propulsion system includes an upper and lower housing with a packerfoot mounted on each end. Each housing has a hydraulic cylinder and ram for moving the propulsion system within the borehole. The propulsion system operates by the lower packerfoot expanding into engagement with the wall of the borehole with the ram in the lower housing extending in the cylinder to force the bit downhole. Simultaneously, the upper packerfoot contracts and moves to the other end of the upper housing. Once the ram in the lower housing completes its stroke, then the hydraulic ram in the upper housing is actuated to propel the bit and motor further downhole as the lower packerfoot contracts and resets at the other end of the lower housing. This cycle is repeated to continuously move the bottom hole assembly within the borehole. The tractor can propel the bottom hole assembly in either direction in the borehole. Flow passages are provided between the packerfeet and housings to allow the passage of drilling fluids through the propulsion system.
Various companies manufacture self-propelled tractors for propelling the bit and pulling steel coiled tubing in the well. These tractors include self-propelled wheels that frictionally engage the wall of the borehole. However, there is very little clearance between the wheels of the propulsion system and the wall of the borehole and problems arise when the wheels encounter ridges or other variances in the dimensions of the wall of the borehole. Further, at times there is an inadequate frictional engagement between the wheels and the wall of the borehole to adequately propel the tractor.
Other companies also offer tractors to walk the end of a wireline down a cased borehole. However, these tractors engage the interior wall of a casing having a known inside dimension. One such tractor is manufactured by Schlumberger.
The use of metal coiled tubing has various deficiencies. Metal coiled tubing tends to buckle the deeper the bottom hole assembly penetrates the borehole. Buckling is particularly acute in deviated wells where gravity does not assist in forcing the tubing downhole. As the tubing buckles, the torque and drag created by the contact with the borehole becomes more difficult to overcome and often makes it impractical or impossible to use coiled tubing to reach distant bypassed hydrocarbon zones. Further, steel coiled tubing often fatigues from cyclic bending early in the drilling process and must be replaced. It has also been found that coiled tubing may be as expensive to use as a conventional drilling system using jointed steel pipe and a rig.
The bottom hole assembly may also include an orienting tool such as a bent sub or housing for directing the trajectory of the borehole. Some types of orienting tools may be adjusted from the surface. Often, prior art orienting tools require a 360° rotation to ratchet to a new direction of inclination.
The bottom hole assembly may include various sensors such as a gamma ray and inclinometer instrument package adjacent the bit and a multiple depth dual frequency borehole compensated resistivity tool. These tools produce data indicating the inclination and azimuth of the bit and the position of the bottom hole assembly with respect to the formation. The bottom hole assembly may also include other sensors for providing other information, such as gyroscopic survey data, resistivity measurements, downhole temperatures, downhole pressures, flow rates, velocity of the power section, gamma ray measurements, fluid identification, formation samples, and pressure, shock, vibration, weight on bit, torque at bit, and other sensor data.
Prior art bottom hole assemblies for rotary drilling and for use with metal coiled tubing include electronic components for collecting data, processing the data downhole, and transmitting the processed information to the surface. The processed information may be transmitted to the surface either by conventional wirelines or by mud pulsed telemetry. In mud pulsed telemetry, the processed information is pulsed back to the surface through the mud column using a valve which opens and closes to produce the pulses. See U.S. Pat. No. 5,586,084. The transmission rate for mud pulsed telemetry, however, is limited.
The electronic components in the bottom hole assembly are also limited in the temperature that they can withstand. Once the environment of the electronic components is subjected to high temperatures, such as 350° F. or greater, for any extended period of time, some of the electronic components may stop functioning. Thus, electronic components, such as semiconductor chips, must be carefully produced and selected to ensure that they can withstand the anticipated heat, shock, and vibration of the bottom hole assembly. Since the life of the electronic components is a function of temperature over time, the higher the downhole temperature, the shorter the life of the electronic components. Thus, not only are the electronic components expensive, but the complexity of the equipment for processing the data downhole causes the bottom hole assemblies to be very expensive particularly for logging while drilling. Such electronic components also reduces the reliability of the bottom hole assembly.
Real time downhole data and information allows real time responses from the surface to downhole conditions. Often, particularly in existing wells, a well plan is designed with a geometric well path to the target hydrocarbon formation. Thus, it is beneficial to have real time information concerning directional drilling, geo-steering, formation evaluation, fluid evaluation, drilling dynamics, propulsion, and intervention, among others. The preferred information and data will vary depending upon the well plan. For example, real time data and information on all of the parameters and characteristics that are determined with logging while drilling and pay zone steering while drilling are beneficial.
Real time information relating to formation evaluation includes information from acoustic caliper tools, neutron porosity tools, formation bulk density tools, sonic tools, and formation resistivity tools. Real time information relating to fluid evaluation includes information from formation testers and magnetic resonance imaging tools indicating various characteristics of the fluids in the surrounding formation including their transportability, identification, and composition.
Real time information on directional drilling and geo-steering includes information on natural gamma radiation, formation resistivity, and azimuth and inclination, including inclination at bit, all of which facilitate pay zone steering from the surface. Accelerometers and inclinometers provide information for directional control.
Real time information on drilling dynamics includes information on weight on bit (WOB), torque at bit (TOB), and pressure while drilling (PWD) including both pressure and temperature. Real time information and data received at the surface and processed by computer would allow instructions to be given to the bottomhole assembly such that the bit RPM and applied weight on the bit could be modified to optimize rate of penetration (ROP) and reduce bit bounce and bit balling. Flow rates and flow pressure could also be modified to improve ROP. See U.S. Pat. No. 5,842,149.
Various real time information and data on downhole parameters and characteristics are beneficial including downhole temperatures, operating temperatures, downhole pressures, operating pressures, annular pressure, pipe pressure, formation pressure, and pressure sampling. Other types of data which may be transmitted to the surface include inclination, azimuth, gyroscopic survey data, resistivity measurements, magnetic resonance (MRI), sonic, neutron density, density, fluid identification, gyroscopic surveying, porosity, flow rates, rpms of the power section, gamma ray measurements, fluid identification, formation samples and other data relating to direction and formation characteristics. Other data relating to drilling includes shock, vibration, weight on bit, torque at bit, rate of penetration, motor rpms, differential pressure across the motor, and other data and information relating to drilling performance parameters.
It is particularly advantageous to provide real-time hydraulics analysis such as the pressure in the annulus of the borehole around the bottomhole assembly. High value wells require a downhole pressure sensor while shallow wells may not require downhole pressure sensors. Bottom hole pressure measurements are particularly beneficial during operating modes including drilling, tripping, circulating, and static modes. These real-time measurements could be used for equivalent circulating density (ECD) monitoring, preventing excessive swab-surge pressures during tripping, and optimizing hole cleaning. In addition, pressure measurement could be used for performing leak off tests, detecting flow in/or kick during drilling, and optimizing drilling practices. Downhole pressure while drilling real-time would be extremely valuable to the operator.
Downhole pressure is a key parameter in drilling. Knowing downhole pressure allows for the adjustment of the wellbore pressure. If wellbore pressure is allowed to decrease below the pore pressure at a certain depth, formation fluids will enter the well. If wellbore pressure exceeds fracture pressure at a certain depth, the formation will fracture and wellbore fluids may enter the formation. Conventionally, downhole pressure is determined by calculating hydrostatic pressure and equivalent circulating density.
It would be valuable to be able to measure downhole pressure particularly in certain situations. During well control due to a kick, circulation is normally stopped to allow the downhole pressure to stabilize and to eliminate any dynamic component of wellbore pressure, while the well is fully shut in. Mud pulse telemetry cannot be used when there is no circulation and thus the operator does not know real-time downhole pressure. Also, it is valuable to know real-time downhole pressure when the drill string becomes stuck. A stuck drill string may prevent circulation. There are other situations where real-time downhole pressure measurement is helpful such as during a leak off test.
Some drilling operations seek to determine formation pressure using measurement while drilling (MWD) techniques. One deficiency of the prior art MWD methods is that all tools transmit pressure measurement data back to the surface on an intermittent basis. Many MWD tools incorporate several measurement tools, such as gamma ray sensors, neutron sensors, and density sensors, and typically only one measurement is transmitted back to the surface at a time. Thus, the interval between pressure data being reported may be as much as 2 minutes. It would be advantageous to provide a high data transmission rate to the surface, eliminate most of the electronics of prior art bottom hole assemblies, and to enhance the reliability and speed of transmission of the data to the surface.
Transmitting the data back to the surface can be accomplished by one of several telemetry methods. One typical prior art telemetry method is mud pulse telemetry. A signal is transmitted by a series of pressure pulses through the drilling fluid. These small pressure variances are received and processed into useful information by equipment at the surface. Mud pulse telemetry does not work when fluids are not being circulated or are being circulated at a slow rate. Therefore, mud pulse telemetry and therefore standard MWD tools have very little utility when the well is shut in and fluid is not circulating.
Although MWD tools can not transmit data via mud pulse telemetry when the well is not circulating, many MWD tools can continue to take measurements and store the collected data in memory. The data can then be retrieved from memory at a later time when the entire drilling assembly is pulled out of the hole. In this manner, the operators can learn whether they have been swabbing the well, i.e. pulling fluids into the borehole, or surging the well, i.e. increasing the wellbore pressure, as the drill string moves through the wellbore. Thus, the data is used for analysis after the fact, as opposed to being used in real-time operations.
Another telemetry method of sending data to the surface is electromagnetic telemetry. A low frequency radio wave is transmitted through the formation to a receiver at the surface. Electromagnetic telemetry is depth limited, and the signal attenuates quickly in water. Therefore, with wells being drilled in deep water, the signal will propagate fairly well through the earth but it will not propagate through the deep water. This method is also highly dependent on formation resistivity and degrades rapidly in less resistive formations typical in deepwater. Thus, a subsea receiver would have to be installed at the mud line, which may not be practical.
Thus, there remains a need in the art for methods and apparatus for determining and adjusting wellbore pressure based on real-time pressure data received from the bottom of a well. Therefore, the embodiments of the present invention are directed to methods and apparatus for using real-time pressure data to automate pressure control procedures that seek to overcome the limitations of the prior art.
The present invention overcomes the deficiencies of the prior art.